Multi-Stage Process and Device for Reducing Environmental Contaminates in Heavy Marine Fuel Oil

ABSTRACT

A multi-stage process for reducing the environmental contaminants in a ISO8217 compliant Feedstock Heavy Marine Fuel Oil involving a core desulfurizing process and an Oxidative desulfurizing process as either a pre-treating step or post-treating step to the core process. The Product Heavy Marine Fuel Oil is compliant with ISO 8217A for residual marine fuel oils and has a sulfur level has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05% wt. to 0.5% wt. A process plant for conducting the process is also disclosed.

BACKGROUND

There are two basic marine fuel types, distillate based marine fuel, and residual based marine fuel. Distillate based marine fuel, also known as Marine Gas Oil (MGO) or Marine Diesel Oil (MDO) comprises petroleum fractions separated from crude oil in a refinery via a distillation process. Gasoil (also known as medium diesel) is a petroleum distillate intermediate in boiling range and viscosity between kerosene and lubricating oil containing a mixture of C₁₀-C₁₉ hydrocarbons. Gasoil is used to heat homes and is used for heavy equipment such as cranes, bulldozers, generators, bobcats, tractors and combine harvesters. Generally maximizing gasoil recovery from residues is the most economic use of the materials by refiners because they can crack gas oils into valuable gasoline and distillates. Diesel oils are very similar to gas oils with diesel containing predominantly contain a mixture of C₁₀-C₁₉ hydrocarbons, which include approximately 64% aliphatic hydrocarbons, 1-2% olefinic hydrocarbons, and 35% aromatic hydrocarbons. Marine Diesels may contain up to 15% residual process streams, and optionally up to no more than 5% volume of polycyclic aromatic hydrocarbons (asphaltenes). Diesel fuels are primarily utilized as a land transport fuel and as blending component with kerosene to form aviation jet fuel.

Residual based fuels or Heavy Marine Fuel Oil (HMFO) comprises a mixture of process residues—the fractions that don't boil or vaporize even under vacuum conditions, and have an asphaltenes content between 3 and 20 percent by weight. Asphaltenes are large and complex polycyclic hydrocarbons with a propensity to form complex and waxy precipitates. Once asphaltenes have precipitated out, they are notoriously difficult to re-dissolve and are described as fuel tank sludge in the marine shipping industry and marine bunker fueling industry.

Large ocean-going ships have relied upon HMFO to power large two stroke diesel engines for over 50 years. HMFO is a blend of aromatics, distillates, and residues generated in the crude oil refinery process. Typical streams included in the formulation of HMFO include: atmospheric tower bottoms (i.e. atmospheric residues), vacuum tower bottoms (i.e. vacuum residues) visbreaker residue, FCC Light Cycle Oil (LCO), FCC Heavy Cycle Oil (HCO) also known as FCC bottoms, FCC Slurry Oil, heavy gas oils and delayed cracker oil (DCO), polycylic aromatic hydrocarbons, reclaimed land transport motor oils and small portions (less than 20% by volume) of cutter oil, kerosene or diesel to achieve a desired viscosity. HMFO has an aromatic content higher than the marine distillate fuels noted above. The HMFO composition is complex and varies with the source of crude oil and the refinery processes utilized to extract the most value out of a barrel of crude oil. The mixture of components is generally characterized as being viscous, high in sulfur and metal content, and high in asphaltenes making HMFO the one product of the refining process that has a per barrel value less than the feedstock crude oil itself.

Industry statistics indicate that about 90% of the HMFO sold contains 3.5 weight % sulfur. With an estimated total worldwide consumption of HMFO of approximately 300 million tons per year, the annual production of sulfur dioxide by the shipping industry is estimated to be over 21 million tons per year. Emissions from HMFO burning in ships contribute significantly to both global air pollution and local air pollution levels.

MARPOL, the International Convention for the Prevention of Pollution from Ships, as administered by the International Maritime Organization (IMO) was enacted to prevent pollution from ships. In 1997, a new annex was added to MARPOL; the Regulations for the Prevention of Air Pollution from Ships—Annex VI to minimize airborne emissions from ships (SOx, NOx, ODS, VOC) and their contribution to air pollution. A revised Annex VI with tightened emissions limits was adopted in October 2008 having effect on 1 Jul. 2010 (hereafter referred to as Annex VI (revised) or simply Annex VI).

MARPOL Annex VI (revised) established a set of stringent emissions limits for vessel operations in designated Emission Control Areas (ECAs). The ECAs under MARPOL Annex VI (revised) are: i) Baltic Sea area—as defined in Annex I of MARPOL—SO_(x) only; ii) North Sea area—as defined in Annex V of MARPOL—SO_(x) only; iii) North American—as defined in Appendix VII of Annex VI of MARPOL—SO_(x), NO_(x) and PM; and, iv) United States Caribbean Sea area—as defined in Appendix VII of Annex VI of MARPOL—SO_(x), NO_(x) and PM.

Annex VI (revised) was codified in the United States by the Act to Prevent Pollution from Ships (APPS). Under the authority of APPS, the U.S. Environmental Protection Agency (the EPA), in consultation with the United States Coast Guard (USCG), promulgated regulations which incorporate by reference the full text of MARPOL Annex VI (revised). See 40 C.F.R. § 1043.100(a)(1). On Aug. 1, 2012 the maximum sulfur content of all marine fuel oils used onboard ships operating in US waters/ECA cannot exceed 1.00% wt. (10,000 ppm) and on Jan. 1, 2015 the maximum sulfur content of all marine fuel oils used in the North American ECA was lowered to 0.10% wt. (1,000 ppm). At the time of implementation, the United States government indicated that vessel operators must vigorously prepare for the 0.10% wt. (1,000 ppm) US ECA marine fuel oil sulfur standard. To encourage compliance, the EPA and USCG refused to consider the cost of compliant low sulfur fuel oil to be a valid basis for claiming that compliant fuel oil was not available for purchase. For the past five years there has been a very strong economic incentive to meet the marine industry demands for low sulfur HMFO, however technically viable solutions have not been realized. There is an on-going and urgent demand for processes and methods for making a low sulfur HMFO that is compliant with MARPOL Annex VI emissions requirements.

Because of the ECAs, all ocean-going ships which operate both outside and inside these ECAs must operate on different marine fuel oils to comply with the respective limits and achieve maximum economic efficiency. In such cases, prior to entry into the ECA, a ship is required to fully change-over to using the ECA compliant marine fuel oil, and to have onboard implemented written procedures on how this is to be undertaken. Similarly change-over from using the ECA compliant fuel oil back to HMFO is not to commence until after exiting the ECA. With each change-over it is required that the quantities of the ECA compliant fuel oils onboard are recorded, with the date, time and position of the ship when either completing the change-over prior to entry or commencing change-over after exit from such areas. These records are to be made in a logbook as prescribed by the ship's flag State, absent any specific requirement the record could be made, for example, in the ship's Annex I Oil Record Book.

The Annex VI (revised) also sets global limits on sulfur oxide and nitrogen oxide emissions from ship exhausts and particulate matter and prohibits deliberate emissions of ozone depleting substances, such as hydro-chlorofluorocarbons. Under the revised MARPOL Annex VI, the global sulfur cap for HMFO was reduced to 3.50% wt. effective 1 January 2012; then further reduced to 0.50% wt, effective 1 Jan. 2020. This regulation has been the subject of much discussion in both the marine shipping and marine fuel bunkering industry. Under the global limit, all ships must use HMFO with a sulfur content of not over 0.50% wt. The IMO has repeatedly indicated to the marine shipping industry that notwithstanding availability of compliant fuel or the price of compliant fuel, compliance with the 0.50% wt. sulfur limit for HMFO will occur on 1 Jan. 2020 and that the IMO expects the fuel oil market to solve this requirement. There has been a very strong economic incentive to meet the international marine industry demands for low sulfur HMFO, however technically viable solutions have not been realized. There is an on-going and urgent demand for processes and methods for making a low sulfur HMFO that is compliant with MARPO1 Annex VI emissions requirements.

IMO Regulation 14 provides both the limit values and the means to comply. These may be divided into methods termed primary (in which the formation of the pollutant is avoided) or secondary (in which the pollutant is formed but removed prior to discharge of the exhaust gas stream to the atmosphere). There are no guidelines regarding any primary methods (which could encompass, for example, onboard blending of liquid fuel oils or dual fuel (gas/liquid) use). In secondary control methods, guidelines (MEPC.184(59)) have been adopted for exhaust gas cleaning systems; in using such arrangements there would be no constraint on the sulfur content of the fuel oils as bunkered other than that given the system's certification. For numerous technical and economic reasons, secondary controls have been rejected by major shipping companies and not widely adopted in the marine shipping industry. The use of secondary controls is not seen as practical solution by the marine shipping industry.

Primary control solutions: A focus for compliance with the MARPOL requirements has been on primary control solutions for reducing the sulfur levels in marine fuel components prior to combustion based on the substitution of HMFO with alternative fuels. However, the switch from HMFO to alternative fuels poses a range of issues for vessel operators, many of which are still not understood by either the shipping industry or the refining industry. Because of the potential risks to ships propulsion systems (i.e. fuel systems, engines, etc. . . . ) when a ship switches fuel, the conversion process must be done safely and effectively to avoid any technical issues. However, each alternative fuel has both economic and technical difficulties adapting to the decades of shipping infrastructure and bunkering systems based upon HMFO utilized by the marine shipping industry.

LNG: The most prevalent primary control solution in the shipping industry is the adoption of LNG as a primary or additive fuel to HMFO. An increasing number of ships are using liquified natural gas (LNG) as a primary fuel. Natural gas as a marine fuel for combustion turbines and in diesel engines leads to negligible sulfur oxide emissions. The benefits of natural gas have been recognized in the development by IMO of the International Code for Ships using Gases and other Low Flashpoint Fuels (the IGF Code), which was adopted in 2015. LNG however presents the marine industry with operating challenges including: on-board storage of a cryogenic liquid in a marine environment will require extensive renovation and replacement of the bunker fuel storage and fuel transfer systems of the ship; the supply of LNG is far from ubiquitous in major world ports; updated crew qualifications and training on operating LNG or duel fuel engines will be required prior to going to sea.

Sulfur Free Bio-fuels: Another proposed primary solution for obtaining compliance with the MARPOL requirements is the substitution of HMFO with sulfur free bio-fuels. Bio-diesel has had limited success in displacing petroleum derived diesel however supply remains constrained. Methanol has been used on some short sea services in the North Sea ECA on ferries and other littoral ships. The wide spread adoption of bio-fuel, such as bio-diesel or methanol, present many challenges to ship owners and the bunker fuel industry. These challenges include: fuel system compatibility and adaptation of existing fuel systems will be required; contamination during long term storage of methanol and biodiesel from water and biological contamination; the heat content of methanol and bio-diesel on a per ton basis is substantially lower than HMFO; and methanol has a high vapor pressure and presents serious safety concerns of flash fires.

Replacement of heavy fuel oil with marine gas oil or marine diesel: A third proposed primary solution is to simply replace HMFO with marine gas oil (MGO) or marine diesel (MDO). The first major difficulty is the constraint in global supply of distillate materials that make up over 90% vol of MGO and MDO. It is reported that the effective spare capacity to produce MGO is less than 100 million metric tons per year resulting in an annual shortfall in marine fuel of over 200 million metric tons per year. Refiners not only lack the capacity to increase the production of MGO, but they have no economic motivation because higher value and higher margins can be obtained from ultra-low sulfur diesel fuel for land-based transportation systems (i.e. trucks, trains, mass transit systems, heavy construction equipment, etc. . . . ).

Blending: Another primary solution is the blending of HMFO with lower sulfur containing fuels such as low sulfur marine diesel (0.1% wt. sulfur) to achieve a Product HMFO with a sulfur content of 0.5% wt. In a straight blending approach (based on linear blending) every 1 ton of HSFO (3.5% sulfur) requires 7.5 tons of MGO or MDO material with 0.1% wt. S to achieve a sulfur level of 0.5% wt. HMFO. One of skill in the art of fuel blending will immediately understand that blending hurts key properties of the HMFO, specifically viscosity and density are substantially altered. Further a blending process may result in a fuel with variable viscosity and density that may no longer meet the requirements for a HMFO.

Further complications may arise when blended HMFO is introduced into the bunkering infrastructure and shipboard systems otherwise designed for unblended HMFO. There is a real risk of incompatibility when the two fuels are mixed. Blending a mostly paraffinic-type distillate fuel (MGO or MDO) with a HMFO having a high aromatic content often correlates with poor solubility of asphaltenes. A blended fuel is likely to result in the precipitation of asphaltenes and/or highly paraffinic materials from the distillate material forming an intractable fuel tank sludge. Fuel tank sludge causes clogging of filters and separators, transfer pumps and lines, build-up of sludge in storage tanks, sticking of fuel injection pumps (deposits on plunger and barrel), and plugged fuel nozzles. Such a risk to the primary propulsion system is not acceptable for a cargo ship in the open ocean.

Lastly blending of HMFO with marine distillate products (MGO or MDO) is not economically feasible. A blender will be taking a high value product (0.1% S marine gas oil (MGO) or marine diesel (MDO)) and blending it 7.5 to 1 with a low value high sulfur HMFO to create a final IMO/MARPOL compliant HMFO (i.e. 0.5% wt. S Low Sulfur Heavy Marine Fuel Oil—LSHMFO). It is expected that LSHMFO will sell at a lower price on a per ton basis than the value of the two blending stocks alone.

Processing of residual oil. For the past several decades, the focus of refining industry research efforts related to the processing of heavy oils (crude oils, distressed oils, or residual oils) has been on upgrading the properties of these low value refinery process oils to create lighter oils with greater value. The challenge has been that crude oil, distressed oil and residues can be unstable and contain high levels of sulfur, nitrogen, phosphorous, metals (especially vanadium and nickel) and asphaltenes. Much of the nickel and vanadium is in difficult to remove chelates with porphyrins. Vanadium and nickel porphyrins and other metal organic compounds are responsible for catalyst contamination and corrosion problems in the refinery. The sulfur, nitrogen, and phosphorous, are removed because they are well-known poisons for the precious metal (platinum and palladium) catalysts utilized in the processes downstream of the atmospheric or vacuum distillation towers.

The difficulties treating atmospheric or vacuum residual streams has been known for many years and has been the subject of considerable research and investigation. Numerous residue-oil conversion processes have been developed in which the goals are same, 1) create a more valuable, preferably distillate range hydrocarbon product; and 2) concentrate the contaminates such as sulfur, nitrogen, phosphorous, metals and asphaltenes into a form (coke, heavy coker residue, FCC slurry oil) for removal from the refinery stream. Well known and accepted practice in the refining industry is to increase the reaction severity (elevated temperature and pressure) to produce hydrocarbon products that are lighter and more purified, increase catalyst life times and remove sulfur, nitrogen, phosphorous, metals and asphaltenes from the refinery stream.

It is also well known in these processes that the nature of the feedstock has a significant influence upon the products produced, catalyst life, and ultimately the economic viability of the process. In a representative technical paper Residual-Oil Hydrotreating Kinetics for Graded Catalyst Systems: Effects of Original and Treated Feedstocks, is stated that “The results revealed significant changes in activity, depending on the feedstock used for the tests. The study demonstrates the importance of proper selection of the feedstocks used in the performance evaluation and screening of candidate catalyst for graded catalyst systems for residual-oil hydrotreatment.” From this one skilled in the art would understand that the conditions required for the successful hydroprocessing of atmospheric residue are not applicable for the successful hydroprocessing of vacuum residue which are not applicable for the successful hydroprocessing of a visbreaker residue, and so forth. Successful reaction conditions depend upon the feedstock. For this reason modern complex refineries have multiple hydroprocessing units, each unit being targeted on specific hydrocarbon stream with a focus on creating desirable and valuable light hydrocarbons and providing a product acceptable to the next downstream process.

A further difficulty in the processing of heavy oil residues and other heavy hydrocarbons is the inherent instability of each intermediate refinery stream. One of skill in the art understands there are many practical reasons each refinery stream is handled in isolation. One such reason is the unpredictable nature of the asphaltenes contained in each stream. Asphaltenes are large and complex hydrocarbons with a propensity to precipitate out of refinery hydrocarbon streams. One of skill in the art knows that even small changes in the components or physical conditions (temperature, pressure) can precipitate asphaltenes that were otherwise dissolved in solution. Once precipitated from solution, asphaltenes can quickly block vital lines, control valves, coat critical sensing devices (i.e. temperature and pressure sensors) and generally result in the severe and very costly disruption and shut down of a unit or the whole refinery. For this reason it has been a long-standing practice within refineries to not blend intermediate product streams (such as atmospheric residue, vacuum residue, FCC slurry oil, etc. . . . ) and process each stream in separate reactors.

In summary, since the announcement of the MARPOL standards reducing the global levels of sulfur in HMFO, refiners of crude oil have not undertaken the technical efforts to create a process for the production of a low sulfur substitute for HMFO. Despite the strong governmental and economic incentives and needs of the international marine shipping industry, refiners have little economic reason to address the removal of environmental contaminates from HMFOs. Instead the global refining industry has been focused upon generating greater value from each barrel of oil by creating light hydrocarbons (i.e. diesel and gasoline) and concentrating the environmental contaminates into increasingly lower value streams (i.e. residues) and products (petroleum coke, HMFO). Shipping companies have focused on short term solutions, such as the installation of scrubbing units, or adopting the limited use of more expensive low sulfur marine diesel and marine gas oils as a substitute for HMFO. On the open seas, most if not all major shipping companies continue to utilize the most economically viable fuel, that is HMFO. There remains a long standing and unmet need for processes and devices that remove the environmental contaminants (i.e. sulfur, nitrogen, phosphorous, metals especially vanadium and nickel) from HMFO without altering the qualities and properties that make HMFO the most economic and practical means of powering ocean going vessels. Further there remains a long standing and unmet need for IMO compliant low sulfur (i.e. 0.5% wt. sulfur) or ultralow (0.10 wt. sulfur) HMFO that is also compliant with the bulk properties required for a merchantable ISO 8217 HMFO.

SUMMARY

It is a general objective to reduce the environmental contaminates from a Heavy Marine Fuel Oil (HMFO) in a multi stage process that minimizes the changes in the desirable properties of the HMFO and minimizes the unnecessary production of by-product hydrocarbons (i.e. light distillate hydrocarbons having C1-C8 and wild naphtha (C5-C20).

A first aspect and illustrative embodiment encompasses a multi-stage process for reducing the environmental contaminants in a Feedstock Heavy Marine Fuel Oil, the process involving: contacting a Feedstock Heavy Marine Fuel Oil with a oxidizing agent under oxidative desulfurizing conditions to give a pre-treated Feedstock Heavy Marine Fuel Oil; mixing a quantity of the pre-treated Feedstock Heavy Marine Fuel Oil with a quantity of Activating Gas mixture to give a Feedstock Mixture; contacting the Feedstock Mixture with one or more catalysts under desulfurizing conditions to form a Process Mixture from the Feedstock Mixture; receiving the Process Mixture and separating the Product Heavy Marine Fuel Oil liquid components of the Process Mixture from the gaseous components and by-product hydrocarbon components of the Process Mixture and, discharging the Product Heavy Marine Fuel Oil.

A second aspect and illustrative embodiment encompasses a process for reducing the environmental contaminants in HMFO, in which the process involves: mixing a quantity of Feedstock Heavy Marine Fuel Oil with a quantity of Activating Gas mixture to give a Feedstock Mixture; contacting the Feedstock Mixture with one or more catalysts under desulfurizing conditions to form a Process Mixture from the Feedstock Mixture; receiving the Process Mixture and separating the liquid components of the Process Mixture from the bulk gaseous components of the Process Mixture; receiving the liquid components and contacting the liquid components with a oxidizing agent under oxidative desulfurizing conditions; subsequently separating any residual gaseous components and by-product hydrocarbon components from the Product Heavy Marine Fuel Oil; and, discharging the Product Heavy Marine Fuel Oil.

A third and fourth aspect and illustrative embodiment encompasses a device for reducing environmental contaminants in a Feedstock HMFO and producing a Product HMFO. The illustrative devices embody the above illustrative processes on a commercial scale.

DESCRIPTION OF DRAWINGS

FIG. 1 is a process flow diagram of a core process to produce Product HMFO.

FIG. 2 is a process flow diagram of a multistage process utilizing a oxidative desulfurizing process to pre-treat the feedstock HMFO and a subsequent core process to produce Product HMFO.

FIG. 3 is a process flow diagram of a multi-stage process utilizing a core process followed by a subsequent oxidative desulfurizing process to produce Product HMFO.

IG. 4 is a basic schematic diagram of a plant to produce Product HMFO utilizing a combination of a oxidative desulfurizing process to pre-treat the feedstock HMFO and a subsequent core process to produce Product HMFO.

FIG. 5 is a basic schematic diagram of a plant to produce Product HMFO utilizing a combination of a core process and subsequent oxidative desulfurizing process to produce Product HMFO.

DETAILED DESCRIPTION

The inventive concepts as described herein utilize terms that should be well known to one of skill in the art, however certain terms are utilized having a specific intended meaning and these terms are defined below:

Heavy Marine Fuel Oil (HMFO) is a petroleum product fuel compliant with the ISO 8217 (2017) standards for the bulk properties of residual marine fuels except for the concentration levels of the Environmental Contaminates.

Environmental Contaminates are organic and inorganic components of HMFO that result in the formation of SO_(x), NO_(x) and particulate materials upon combustion.

Feedstock HMFO is a petroleum product fuel compliant with the ISO 8217 (2017) standards for the bulk properties of residual marine fuels except for the concentration of Environmental Contaminates, preferably the Feedstock HMFO has a sulfur content greater than the global MARPOL standard of 0.5% wt. sulfur, and preferably and has a sulfur content (ISO 14596 or ISO 8754) between the range of 5.0% wt. to 1.0% wt.

Product HMFO is a petroleum product fuel compliant with the ISO 8217 (2017) standards for the bulk properties of residual marine fuels and achieves a sulfur content lower than the global MARPOL standard of 0.5% wt. sulfur (ISO 14596 or ISO 8754), and preferably a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05% wt. to 1.0% wt.

Activating Gas: is a mixture of gases utilized in the process combined with the catalyst to remove the environmental contaminates from the Feedstock HMFO.

Fluid communication: is the capability to transfer fluids (either liquid, gas or combinations thereof, which might have suspended solids) from a first vessel or location to a second vessel or location, this may encompass connections made by pipes (also called a line), spools, valves, intermediate holding tanks or surge tanks (also called a drum).

Merchantable quality: is a level of quality for a residual marine fuel oil so that the fuel is fit for the ordinary purpose it is intended to serve (i.e. serve as a residual fuel source for a marine ship) and can be commercially sold as and is fungible with heavy or residual marine bunker fuel.

Bbl or bbl: is a standard volumetric measure for oil; 1 bbl=0.1589873 m³; or 1 bbl=158.9873 liters; or 1 bbl=42.00 US liquid gallons.

Bpd: is an abbreviation for Bbl per day.

SCF: is an abbreviation for standard cubic foot of a gas; a standard cubic foot (at 14.73 psi and 60° F.) equals 0.0283058557 standard cubic meters (at 101.325 kPa and 15° C).

The inventive concepts are illustrated in more detail in this description referring to the drawings, in which FIG. 1 shows the generalized block process flows for a core process of reducing the environmental contaminates in a Feedstock HMFO and producing a Product HMFO. A predetermined volume of Feedstock HMFO (2) is mixed with a predetermined quantity of Activating Gas (4) to give a Feedstock Mixture. The Feedstock HMFO utilized generally complies with the bulk physical and certain key chemical properties for a residual marine fuel oil otherwise compliant with ISO8217:2017 exclusive of the Environmental Contaminates. More particularly, when the Environmental Contaminate is sulfur, the concentration of sulfur in the Feedstock HMFO may be between the range of 5.0% wt. to 1.0% wt. The Feedstock HMFO should have bulk physical properties that are required of an ISO8217:2017 compliant HMFO of: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s and a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³ and a CCAI is 780 to 870 and a flash point (ISO 2719) no lower than 60.0 C. Other properties of the Feedstock HMFO connected to the formation of particulate material (PM) include: a maximum total sediment—aged (ISO 10307-2) of 0.10% wt. and a maximum carbon residue—micro method (ISO 10370) between the range of 18.00% wt. and 20.00% wt. and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg. Potential Environmental Contaminates other than sulfur that may be present in the Feedstock HMFO over the ISO requirements may include vanadium, nickel, iron, aluminum and silicon substantially reduced by the process of the present invention. However, one of skill in the art will appreciate that the vanadium content serves as a general indicator of these other Environmental Contaminates. In one preferred embodiment the vanadium content is ISO compliant so the Feedstock MHFO has a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg.

As for the properties of the Activating Gas, the Activating Gas should be selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane. The mixture of gases within the Activating Gas should have an ideal gas partial pressure of hydrogen (p_(H2)) greater than 80% of the total pressure of the Activating Gas mixture (P) and more preferably wherein the Activating Gas has an ideal gas partial pressure of hydrogen (p_(H2)) greater than 95% of the total pressure of the Activating Gas mixture (P). It will be appreciated by one of skill in the art that the molar content of the Activating Gas is another criteria the Activating Gas should have a hydrogen mole fraction in the range between 80% and 100% of the total moles of Activating Gas mixture, more preferably wherein the Activating Gas has a hydrogen mole fraction between 80% and 99% of the total moles of Activating Gas mixture

The Feedstock Mixture (i.e. mixture of Feedstock HMFO and Activating Gas) is brought up to the process conditions of temperature and pressure and introduced into a first vessel, preferably a reactor vessel, so the Feedstock Mixture is then contacted with one or more catalysts (8) to form a Process Mixture from the Feedstock Mixture.

The core process conditions are selected so the ratio of the quantity of the Activating Gas to the quantity of Feedstock HMFO is 250 scf gas/bbl of Feedstock HMFO to 10,000 scf gas/bbl of Feedstock HMFO; and preferably between 2000 scf gas/bbl of Feedstock HMFO 1 to 5000 scf gas/bbl of Feedstock HMFO more preferably between 2500 scf gas/bbl of Feedstock HMFO to 4500 scf gas/bbl of Feedstock HMFO. The process conditions are selected so the total pressure in the first vessel is between of 250 psig and 3000 psig; preferably between 1000 psig and 2500 psig, and more preferably between 1500 psig and 2200 psig The process conditions are selected so the indicated temperature within the first vessel is between of 500 F to 900 F, preferably between 650 F and 850 F and more preferably between 680 F and 800 F The process conditions are selected so the liquid hourly space velocity within the first vessel is between 0.05 oil/hour/m³ catalyst and 1.0 oil/hour/m³ catalyst; preferably between 0.08 oil/hour/m³ catalyst and 0.5 oil/hour/catalyst; and more preferably between 0.1 oil/hour/m³ catalyst and 0.3 oil/hour/m³ catalyst to achieve deep desulfurization with product sulfur levels below 0.1 ppmw.

One of skill in the art will appreciate that the core process conditions are determined to consider the hydraulic capacity of the unit. Exemplary hydraulic capacity for the treatment unit may be between 100 bbl of Feedstock HMFO/day and 100,000 bbl of Feedstock HMFO/day, preferably between 1000 bbl of Feedstock HMFO/day and 60,000 bbl of Feedstock HMFO/day, more preferably between 5,000 bbl of Feedstock HMFO/day and 45,000 bbl of Feedstock HMFO/day, and even more preferably between 10,000 bbl of Feedstock HMFO/day and 30,000 bbl of Feedstock HMFO/day

The core process may utilize one or more catalyst systems selected from the group consisting of: an ebulliated bed supported transition metal heterogeneous catalyst, a fixed bed supported transition metal heterogeneous catalyst, and a combination of ebulliated bed supported transition metal heterogeneous catalysts and fixed bed supported transition metal heterogeneous catalysts. One of skill in the art will appreciate that a fixed bed supported transition metal heterogeneous catalyst will be the technically easiest to implement and is preferred. The transition metal heterogeneous catalyst comprises a porous inorganic oxide catalyst carrier and a transition metal catalyst. The porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier. The transition metal component of the catalyst is one or more metals selected from the group consisting of group 6, 8, 9 and 10 of the Periodic Table. In a preferred and illustrative embodiment, the transition metal heterogeneous catalyst is a porous inorganic oxide catalyst carrier and a transition metal catalyst, in which the preferred porous inorganic oxide catalyst carrier is alumina and the preferred transition metal catalyst is Ni—Mo, Co—Mo, Ni—W or Ni—Co—Mo

The Process Mixture (10) in this core process is removed from the first vessel (8) and from being in contact with the one or more catalyst and is sent via fluid communication to a second vessel (12), preferably a gas-liquid separator or hot separators and cold separators, for separating the liquid components (14) of the Process Mixture from the bulk gaseous components (16) of the Process Mixture. The gaseous components (16) are treated beyond the battery limits of the immediate process. Such gaseous components may include a mixture of Activating Gas components and lighter hydrocarbons (mostly methane, ethane and propane but some wild naphtha) that may have been unavoidably formed as part of the by-product hydrocarbons from the process.

The Liquid Components (16) in this core process are sent via fluid communication to a third vessel (18), preferably a fuel oil product stripper system, for separating any residual gaseous components (20) and by-product hydrocarbon components (22) from the Product HMFO (24). The residual gaseous components (20) may be a mixture of gases selected from the group consisting of: nitrogen, hydrogen, carbon dioxide, hydrogen sulfide, gaseous water, C1-C5 hydrocarbons. This residual gas is treated outside of the battery limits of the immediate process, combined with other gaseous components (16) removed from the Process Mixture (10) in the second vessel (12). The liquid by-product hydrocarbon component, which are condensable hydrocarbons unavoidably formed in the process (22) may be a mixture selected from the group consisting of C5-C20 hydrocarbons (wild naphtha) (naphtha—diesel) and other condensable light liquid (C4-C8) hydrocarbons that can be utilized as part of the motor fuel blending pool or sold as gasoline and diesel blending components on the open market.

The Product HMFO (24) resulting from the core process is discharged via fluid communication into storage tanks beyond the battery limits of the immediate process. The Product HMFO complies with ISO8217:2017 and has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % to 1.0 mass % preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % ppm and 0.7 mass % and more preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.1 mass % and 0.5 mass %. The vanadium content of the Product HMFO is also ISO compliant with a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg, preferably a vanadium content (ISO 14597) between the range of200 mg/kg and 300 mg/kg and more preferably a vanadium content (ISO 14597) between the range of 50 mg/kg and 100 mg/kg.

The Feedstock HFMO should have bulk physical properties that are ISO compliant of: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s; a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³; a CCAI is in the range of 780 to 870; a flash point (ISO 2719) no lower than 60.0 C a maximum total sediment—aged (ISO 10307-2) of 0.10 mass %; a maximum carbon residue—micro method (ISO 10370) between the range of 18.00 mass % and 20.00 mass %, and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.

The Product HMFO will have a sulfur content (ISO 14596 or ISO 8754) between 1% and 10% of the maximum sulfur content of the Feedstock Heavy Marine Fuel Oil. That is the sulfur content of the Product will be reduced by about 80% or greater when compared to the Feedstock HMFO. Similarly, the vanadium content (ISO 14597) of the Product Heavy Marine Fuel Oil is between 1% and 10% of the maximum vanadium content of the Feedstock Heavy Marine Fuel Oil. One of skill in the art will appreciate that the above data indicates a substantial reduction in sulfur and vanadium content indicate a process having achieved a substantial reduction in the Environmental Contaminates from the Feedstock HMFO while maintaining the desirable properties of an ISO compliant HMFO.

As a side note, the residual gaseous component is a mixture of gases selected from the group consisting of: nitrogen, hydrogen, carbon dioxide, hydrogen sulfide, gaseous water, light hydrocarbons. An amine scrubber will effectively remove the hydrogen sulfide content which can then be processed using technologies and processes well known to one of skill in the art. In one preferable illustrative embodiment, the hydrogen sulfide is converted into elemental sulfur using the well-known Claus process. An alternative embodiment utilizes a proprietary process for conversion of the Hydrogen sulfide to hydro sulfuric acid. Either way, the sulfur is removed from entering the environment prior to combusting the HMFO in a ships engine. The cleaned gas can be vented, flared or more preferably recycled back for use as Activating Gas.

The by-product hydrocarbon components are a mixture of C5-C20 hydrocarbons (wild naphtha) (naphtha—diesel) which can be directed to the motor fuel blending pool or sold over the fence to an adjoining refinery or even utilized to fire the heaters and combustion turbines to provide heat and power to the process. These by product hydrocarbons which are the result of hydrocracking reactions should be less than 10% wt. , preferably less than 5% wt. and more preferably less than 2% wt. of the overall process mass balance.

The Product HMFO (24) is discharged via fluid communication into storage tanks beyond the battery limits of the immediate process.

Oxidative Desulfurizing Process: It will be appreciated by one of skill in the art, that the conditions utilized in the core process have been intentionally selected to minimize cracking of hydrocarbons, but at the same time remove significant levels of sulfur from the Feedstock HMFO. However, one of skill in the art will also appreciate that there may be certain “hard sulfur” compounds present in the Feedstock HMFO removal of which would require elevated temperatures, increased hydrogen pressures, longer residence times for removal all of which would tend to cause cracking of hydrocarbons and an adverse impact upon the desirable bulk properties of the Product HMFO. Process and systems for the removal of these “hard sulfur” compounds may be required to achieve an ultra-low sulfur (i.e. sulfur content (ISO 14596 or ISO 8754) less than 0.1% wt. and preferably lower than 0.05% wt. sulfur content (ISO 14596 or ISO 8754)) Product HMFO. These processes and systems must achieve this without substantially altering the desirable bulk properties (i.e. compliance with ISO 8217:2017 exclusive of sulfur content) of the Product HMFO

In the following description, items already described above as part of the core process have retained the same numbering and designation for ease of description. As show in FIG. 2, an oxidative desulfurizing unit 3 can be utilized to pre-treat the Feedstock HMFO prior to mixing with the Activating Gas 4 as part of the core process disclosed above. While simplistically represented in this drawing, the oxidative desulfurizing unit 3 may be complex and comprise multiple reactor units and liquid/solid or liquid/liquid separation units, however the oxidative desulfurizing unit may be as simple as a fixed bed, flow through/contact reactor vessel in which the HMFO simply contacts/flows over a oxidizing agent supported on an inert solid. While a single oxidative desulfurizing unit may be used, it may be advantageous, and it is preferable to have multiple oxidative desulfurizing unit in parallel with each other to allow for one unit to be active while a second or third unit are being reloaded with oxidizing agent material, the oxidizing agent is being regenerated, or the unit is undergoing turnaround in preparation for use. Such an arrangement involving multiple parallel contact vessels with accompanying pipes/switching valves, etc. . . . is well within the abilities of one of skill in the art of refinery process design and operation.

In an embodiment of the present invention, the HMFO stream is contacted with an oxidant to convert the organo-sulfur compounds into oxidized organo-sulfur compounds such as sulfones and sulfoxides. The resulting HMFO stream containing the oxidized sulfur compounds can then be separated from the oxidizing agent (i.e. by physical separation or decomposition of any residual oxidizing agent) and followed by removal of the oxidized organo-sulfur compounds. This last step may involve extractive contact with a selective solvent having a greater selectivity for the oxidized sulfur compounds than for the HMFO to produce a solvent containing at least a portion of the oxidized sulfur compounds and a HMFO stream having a reduced concentration of oxidized sulfur compounds; or alternatively it may simply involve heating the HMFO stream containing the oxidized sulfur compounds to cause the thermal decomposition of the sulfones and sulfoxides to gaseous sulfur compounds (i.e. hydrogen sulfide and/or sulfur dioxides) and residual hydrocarbon materials which are readily separated/treated using known methods.

Turning now to the oxidizing agent material utilized in the oxidative desulfurizing unit 3, a number of oxidizing agents may be useful in the first or oxidative desulfurization step. The oxidizing agent may be selected from the group consisting of a gaseous oxidant, an organic oxidant, an inorganic oxidant, a bio-oxidant or combinations of these. When used in combination, a mixture of two oxidizing agents may be used in the same reactor, for example, gaseous oxidant (ozone or oxygen) and organic oxidizing agent or inorganic oxidizing agent. Alternatively, the different oxidizing agents can be utilized in a cascading series of reactors that are complimentary to each other. For example, an initial stage of may be conducted using a bio-oxidizing agent and a subsequent stage with a stronger oxidizing agent (i.e. gaseous oxidant, an organic oxidant, an inorganic oxidant, or combinations of these). For example, the combination of Ozone and t-butylhydroperoxide as a pair of oxidizing agents is utilized to oxidize sulfur compounds in diesel as disclosed in U.S. Pat. No. 9,365,780 (the contents of which are incorporated herein by reference). Optimization of the process and compatibility aspects can be determined by one of skill in the art by routine and systematic testing of HMFO material and oxidizing agents.

In one embodiment, the oxidizing agent can be a gaseous oxidant selected from the group consisting ozone, nitrogen oxides, molecular oxygen, air, oxygen depleted air (i.e. air in which the concentration of oxygen can be less than about 21 vol. %). When oxygen is utilized, it may be desirable to include a promoter material such as metal from group 5A and Group 8 of the Periodic Table or their salts or oxides, more specifically platinum, palladium, nickel and vanadium. These promotor materials are preferably supported on suitable materials, for example alumina, silica or activated carbon. Where the support material has cracking tendencies, such as alumina, the support material may be first treated with alkali metal hydroxides or ammonia compounds to deactivate the support. One of skill in the art will appreciate that the use of such promotors will improve the selective oxidation step in a shorter time period and/or lower temperature and milder conditions. In one embodiment, the oxidizing step is conducted in a temperature range of 80° C. to 180° C., conditions under which the HMFO is sufficiently fluid like to be pumped, stirred, etc. . . . and the amount of gaseous oxidant is in the range of 1 and 6 active oxygen equivalents to each sulfur molecule equivalents in the feedstock. Preferably when oxygen or air is utilized, the temperature will lie between the range of 130° C. and 180° C. and the reaction period will be between 2 hours and 20 hours.

In another embodiment the oxidizing agent can be an organic oxidant selected from the group consisting of alkyl hydroperoxides, such as tert-butyl hydroperoxide (TBHP), cumyl hydroperoxide (CHP) and/or ethylbenzene hydroperoxide (EBHP); peroxides, such as kerosene peroxide; percarboxylic acids, such as peracetic acid. In some instances when an organic oxidizing agent is utilized, a suitable catalyst which is capable of reacting sulfur compounds and organic oxidizing agent to produce sulfones may be utilized. A preferred suitable catalyst when alkyl hydroperoxides are utilized may be selected from the group consisting of: heterogeneous titanium(IV) catalyst having the general formula Ti(OOR)(OH)(OR′)₂; R is selected from the group consisting of hydride, alkyl groups, aryl groups, and/or alkylaryl groups; and wherein R′ is selected from the group consisting of ethylene glycol, glycerol, sorbitol, xylitol and/or mixtures thereof; a molybdenum compound, such as MoO₃, MgMoO₄ supported on an inorganic oxide support such as alumina, silica, MgO, ZrO₂ and ZnO. When such combinations are utilized, the operating conditions in the organic sulfur oxidation zone can include a pressure from about 100 kPa (0 psig) to about 3550 kPa (500 psig) and a temperature from about 49° C. (120° F.) to about 180° C. (356° F.).

In another embodiment the oxidizing agent can be an inorganic oxidant is selected from the group consisting of aqueous ferrate solution, aqueous permanganate solution. In such an embodiment, simple contacting of the HMFO with an aqueous solution of the oxidizing agent will be sufficient to cause the oxidation of the organo sulfur compounds. However, this must be done under carefully controlled circumstances to avoid excess oxidizing agent being present and potentially adversely impacting the non-sulfur containing components of the HMFO. A counter-current reactor may be useful in these instances as it will limit the contact time and allow the careful control and monitoring of the concentration of oxidizing agent relative to the on-line measured concentration of sulfur compounds. That is to say the control system should be able to automatically monitor the level of sulfur compounds present in the feed HMFO on a real-time or nearly real time basis and use this data to adjust the amount of oxidizing agent introduced into the reactor. Similar feed properties/reactant feed level control loops are well known to and well within the abilities of one of skill in the art to implement.

In another embodiment the oxidizing agent can be a bio-oxidizing agent in aqueous solution such as a microorganisms selected from the group which is capable of a selective oxidation of the sulfur in organic sulfur compounds, to the sulfoxide and/or sulfone form, without concomitant oxidation of other components of the HMFO. Microorganisms known to perform selective sulfur oxidation include Rhodococcus (previously identified as Arthrobacter) strains ATCC 55309 and ATCC 55310 (U.S. Pat. No. 5,607,857), Rhodococcus rhodochrous strain ATCC 53968 (U.S. Pat. No. 5,104,801) Bacillus sphaericus strain ATCC 53969 (U.S. Pat. No. 5,002,888), Rhodococcus erythropolis strains N1-36 and D-1 (Wang, P. and Krawiec, S. (1994); microorganisms reported to desulfurization of dibenzothiophene to 2-hydroxybiphenyl. Arch. Microbiol. 161, 266-271, Izumi, Y., Ohshiro, T., Ogino, H., Hine, Y. and Shimao, M. (1994); selective desulfurization of dibenzothiophene by Rhodococcus erythropolis D-1. Appl. Environ. Microbiol. 60, 223-226); Corynebacterium strain SY1 (Omori, T., Monna, L., Saiki, Y., and Kodama, T. (1992); desulfurization of dibenzothiophene by Corynebacterium sp. Stain SY1. App. Envir. Micro. 58, 911-915) and Brevibacterium strain DO (van Afferden, M., Schacht, S., Klein, J. and Truper, H. G. (1990); °radation of dibenzothiophene by Brevibacterium sp. DO. Arch. Microbiol. 153, 324-328). Preferable examples include Rhodococcus species ATCC 55309, Rhodococcus species ATCC 55310, or combinations thereof. When a bio-oxidizing agent is utilized the HMFO material to be desulfurized will be at mild temperatures (0-100° C.), in the presence of oxygen, brought into contact with the biocatalysts (either whole cell, cell fraction, or enzyme preparation), contained within an aqueous buffer containing mineral salts, and if required a carbon, nitrogen and phosphorous source, and if required cofactors (e.g., NAD(P)H), for a sufficiently long period of time to allow the conversion of all, or part of, the organic sulfur into the corresponding sulfoxides and sulfones. Following the bio-oxidation step, the treated HMFO is separated from the biocatalysts, by any of a variety of standard techniques including gravity separation, gravity separation facilitated by heating, gravity separation facilities by an applied electrical potential (as in crude oil electrostatic desalters), and centrifugation. Alternatively, the bio-oxidizing agent may be immobilized in a gel or solid support, in which case the HMFO will be brought in contact with the bio-oxidizing agent and subsequently separated via an outlet port from the reactor without the need for further separation steps. Depending upon the nature of any subsequent process for removal of the oxidized sulfur compounds, separation of water and/or water bio-oxidizing agent from the HMFO may not be required. For example, if thermal decomposition is utilized, the heat will not only decompose the oxidized sulfur compounds, but also effectively remove and/or sterilize the HMFO of any active microbial content.

Following the oxidative desulfurization step, the sulfones and sulfoxides will be removed from the HMFO material. A range of potential removal processes are known in the art including: thermal decomposition; solvent extraction; caustic wash; contact with solid absorbents, each of which is described below. One of skill in the art will appreciate that one or more of these methods may be utilized to achieve the optimal removal of the oxidized sulfur compounds from the HMFO, it is contemplated that a combinations of these steps may be utilized. As noted above, while simplistically shown in the Figures, the removal of the oxidized sulfur compounds from the HMFO may involve stirred tank reactors, thermal reactors, liquid solid separators such centrifuges or settling tanks, concurrent or counter current contacting or extraction processes all of which are conventional and readily apparent to one of skill in the art of chemical and refining processes based on routine lab scale pilot testing.

In one embodiment thermal decomposition may be utilized subsequent to the oxidative desulphurization step. Preferably this step is carried out at temperatures above, 200° C. and preferably above 250° C. and more preferably in the 300-400° C. range. Under these conditions the oxidized sulfur compounds are thermally decomposed into organic components (mostly aliphatic and aromatic hydrocarbons) and gaseous sulfur compounds, such as sulfur dioxide or hydrogen sulfide. The thermal decomposition step may be carried out in the presence of promoter materials such as ferric oxide on alumina, bauxite, silica, silica-alumina and the like. A small amount of inert carrier gas may be utilized to °as the HMFO and remove the gaseous sulfur components being liberated. In one such embodiment, the thermal decomposition takes place at the same time as the by-product hydrocarbons (i.e. lights and wild naphtha) and other entrained gases are separated from the Product HMFO. In another embodiment a tube furnace or similar heated flow through reactor will be utilized to allow for a continuous operation and flow of HMFO material. One of skill in the art will appreciate that the generation of sulfur dioxides and/or hydrogen sulfide will require scrubbers to prevent the emissions of such compounds into the environment. Such systems are well known to one of skill in the art and need to be described in detail herein.

In another illustrative embodiment, solvent extraction using polar organic fluids such as methanol, acetone, acetonitrile, dimethylformamide (DMF) or similar fluids that are not generally soluble in HMFO can be utilized in removing oxidized sulfur compounds from the HMFO. Selection of the appropriate polar extraction fluid will be simply a matter of lab testing to determine the optimal extraction fluid. In one embodiment, it is expected that methanol will be the most economical and useful organic polar fluids for extracting the oxidized sulfur compounds from the HMFO. In another alternative embodiment, ionic liquids may be utilized as the extraction medium. Generally, ionic liquid materials are non-aqueous, organic salts composed of a cation and an anion. These materials have relatively low melting points when compared to ionic solids (such a table salt or other common ionic solids), often below 100° C., undetectable vapor pressure, and good chemical and thermal stability. The cationic charge of the salt is localized over hetero atoms, such as nitrogen, phosphorous, and sulfur and the anions may be any inorganic, organic, or organometallic species. The benefits of the ionic liquid extraction technology for the extraction of the oxidized sulfur compounds from the HMFO are very mild process conditions (i.e. conditions that do not alter the bulk properties of the ISO 8217 2017 compliant feedstock HMFO), high efficiency in removal of oxidized sulfur compounds from the HMFO, and an environmental benign process. An ionic liquid can be selected from the group liquid and semi-liquid salts having the general formula Q+ A− wherein Q+ (also known as the cationic component) for example quaternary ammonium cations and quaternary phosphonium cations and A− represents the anionic component which may be any anion that forms a liquid or semi-liquid salt at or below the temperature used in the extraction step which should be preferably below 300° C. and more preferably below about 100° C. A wide range of ionic liquids may be useful in extracting oxidized sulfur compounds from the HMFO including but not limited to ionic liquids consists essentially of imidazolium ionic liquids, pyridinium ionic liquids, phosphonium ionic liquids, lactamium ionic liquids, ammonium ionic liquids, pyrrolidinium ionic liquids, and combinations thereof. In still another embodiment, the ionic liquid is selected from the group consisting of imidazolium ionic liquids, pyridinium ionic liquids, phosphonium ionic liquids, lactamium ionic liquids, ammonium ionic liquids, pyrrolidinium ionic liquids, and combinations thereof. Imidazolium, pyridinium, lactamium, ammonium, and pyrrolidinium ionic liquids have a cation comprising at least one nitrogen atom. Phosphonium ionic liquids have a cation comprising at least one phosphorous atom. This extraction process utilizing either polar organic liquids or ionic liquids may be conducted using batch extraction, concurrent or counter current extraction techniques well known to one of skill in the art. Regeneration or recovery of the extracting liquid will depend upon the nature of the fluid utilized, however with methanol a simple distillation may be useful and with ionic liquids regeneration by exposure to a reducing environment such a hydrogen gas followed by separation may be utilized.

In another embodiment, an aqueous caustic containing wash fluid contacts the oxidized HMFO with caustic inorganic oxides (alkali oxides and hydroxides) which may be dissolved or supported on inert supports. The contact between the oxidized HMFO and the caustic aqueous solution may be facilitated by contacting caustic with hanging fiber barrier (such as that disclosed in U.S. Pat. No. 8,574,429, the contents of which are incorporated herein by reference), capillary tubes, or microemulsion blender/contactor all of which are known to one of skill in the art of mixing aqueous solutions with heavy/viscous hydrocarbons. In such instances, it may be desirable to include a phase transfer agent such as polyol or other similar surfactant utilized in the water washing of crude oil in a desalter. Alternatively, the caustic material can be immobilized and supported on an inert material such as caustic treated alumina or silica.

In another illustrative embodiment, absorbents which selectively adsorb sulfones and sulfoxides may also be utilized to remove the oxidized sulfur compounds from the HMFO in the process of the present invention. Preferred adsorbents include silica gel, zeolites and alumina. Preferred operating conditions in an adsorption zone include a pressure from about 100 kPa (14.7 psig) to about 3550 kPa (500 psig) and a temperature from about 40° C. (104° F.) to about 200° C. (392° F.). Regeneration of spent adsorbent containing sulfones is preferably conducted by contacting the spent adsorbent with a suitable desorbant including pentane, hexane, benzene, toluene, xylene and admixtures thereof, for example. Once the sulfone is removed from the spent adsorbent, the regenerated adsorbent containing a reduced level of sulfone may be reused to adsorb additional sulfone. The flow of streams may be up flow or down flow through vessels.

Without regard to the type of oxidizing agent/removal process utilized in the oxidative desulfurizing unit, the fluid effluent from oxidative desulfurizing unit 3 need not have all or even substantially all of the sulfur compounds in the HMFO feed removed. Rather the concept is remove at least a portion of the sulfur compounds to reduce the overall sulfur load on the subsequent process units. In this way one may be able to achieve a level of sulfur reduction for a HMFO not previously achieved while at the same time minimizing the cracking of hydrocarbons and maintaining the desirable bulk properties of the HMFO. In one illustrative embodiment, the fluid effluent from oxidative desulfurizing unit 3 preferably contains less than about 90 weight percent of the amount of sulfur in the fluid feed charged to oxidative desulfurizing unit 3, more preferably less than about 75 weight percent of the amount of sulfur in the fluid feed, and most preferably less than 50 weight percent of the amount of sulfur in the fluid feed.

An alternative illustrative embodiment is shown in FIG. 3 in which a oxidative desulfurizing unit 17 is utilized subsequent to the core sulfur removal process step, but prior to the separation of the Product HMFO 24 from any Residual Gas 20 and By-Product 22 (i.e. mostly C1-C4 hydrocarbons, and wild naphtha). In such a configuration the oxidative desulfurizing unit effectively acts as a polishing unit with the goal of removing “hard sulfur” compounds present in the HMFO that are not removed under the conditions in the core sulfur removal process step. As with the pre-treatment oxidative desulfurizing unit described above, the conditions in this post-treatment oxidative desulfurizing unit are moderate. It is believed that because this step of the process is conducted under very modest conditions (i.e. moderately elevated temperatures sufficient to make the HMFO liquid-like) the oxidizing agent materials used in this process will have minimal to no impact upon the bulk physical properties of the product HMFO. In this way one may be able to achieve a level of sulfur reduction for a HMFO not previously achieved while at the same time minimizing the cracking of hydrocarbons and maintaining the desirable bulk properties of the HMFO. In one illustrative embodiment, the fluid effluent from oxidative desulfurizing unit 17 preferably contains less than about 90 weight percent of the amount of sulfur in the fluid feed charged to oxidative desulfurizing unit 17, more preferably less than about 75 weight percent of the amount of sulfur in the fluid feed, and most preferably less than 50 weight percent of the amount of sulfur in the fluid feed.

Product HMFO The Product HFMO resulting from the disclosed illustrative process is of merchantable quality for sale and use as a heavy marine fuel oil (also known as a residual marine fuel oil or heavy bunker fuel) and exhibits the bulk physical properties required for the Product HMFO to be an ISO compliant (i.e. ISO8217:2017) residual marine fuel oil exhibiting the bulk properties of: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s; a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³; a CCAI is in the range of 780 to 870; a flash point (ISO 2719) no lower than 60.0 C a maximum total sediment—aged (ISO 10307-2) of 0.10% wt.; a maximum carbon residue—micro method (ISO 10370) between the range of 18.00% wt. and 20.00% wt., and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.

The Product HMFO has a sulfur content (ISO 14596 or ISO 8754) less than 0.5 wt % and preferably less than 0.1% wt. and is fully compliant with the IMO Annex VI (revised) requirements for a low sulfur and preferably an ultra-low sulfur HMFO. That is the sulfur content of the Product HMFO has been reduced by about 90% or greater when compared to the Feedstock HMFO. Similarly, the vanadium content (ISO 14597) of the Product Heavy Marine Fuel Oil is less than 10% and more preferably less than 1% of the maximum vanadium content of the Feedstock Heavy Marine Fuel Oil. One of skill in the art will appreciate that a substantial reduction in sulfur and vanadium content of the Feedstock HMFO indicates a process having achieved a substantial reduction in the Environmental Contaminates from the Feedstock HMFO; of equal importance is that this has been achieved while maintaining the desirable properties of an ISO8217:2017compliant HMFO.

The Product HMFO not only complies with ISO8217:2017 (and is merchantable as a residual marine fuel oil or bunker fuel), the Product HMFO has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05% wt. to 1.0% wt. preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.05% wt. ppm and 0.5% wt. and more preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.1% wt. and 0.5% wt. The vanadium content of the Product HMFO is well within the maximum vanadium content (ISO 14597) required for an ISO8217:2017 residual marine fuel oil exhibiting a vanadium content lower than 450 ppm mg/kg, preferably a vanadium content (ISO 14597) lower than 300 mg/kg and more preferably a vanadium content (ISO 14597) between the range of 50 mg/kg and 100 mg/kg.

One knowledgeable in the art of marine fuel blending, bunker fuel formulations and the fuel logistical requirements for marine shipping fuels will readily appreciate that without further compositional changes or blending, the Product HMFO can be sold and used as a low sulfur MARPOL Annex VI compliant heavy (residual) marine fuel oil that is a direct substitute for the high sulfur heavy (residual) marine fuel oil or heavy bunker fuel currently in use. One illustrative embodiment is an ISO8217:2017 compliant low sulfur heavy marine fuel oil comprising (and preferably consisting essentially of) a 100% hydroprocessed ISO8217:2017 compliant high sulfur heavy marine fuel oil, wherein the sulfur levels of the hydroprocessed ISO8217:2017 compliant high sulfur heavy marine fuel oil is greater than 0.5% wt. and wherein the sulfur levels of the ISO8217:2017 compliant low sulfur heavy marine fuel oil is less than 0.5% wt. Another illustrative embodiment is an ISO8217:2017 compliant ultra-low sulfur heavy marine fuel oil comprising (and preferably consisting essentially of) a 100% hydroprocessed ISO8217:2017 compliant high sulfur heavy marine fuel oil, wherein the sulfur levels of the hydroprocessed ISO8217:2017 compliant high sulfur heavy marine fuel oil is greater than 0.5% wt. and wherein the sulfur levels of the ISO8217:2017 compliant low sulfur heavy marine fuel oil is less than 0.1% wt.

As a result of the present invention, multiple economic and logistical benefits to the bunkering and marine shipping industries can be realized. More specifically the benefits include minimal changes to the existing heavy marine fuel bunkering infrastructure (storage and transferring systems); minimal changes to shipboard systems are needed to comply with emissions requirements of MARPOL Annex VI (revised); no additional training or certifications for crew members will be needed, amongst the realizable benefits. Refiners will also realize multiple economic and logistical benefits, including: no need to alter or rebalance the refinery operations and product streams to meet a new market demand for low sulfur or ultralow sulfur HMFO; no additional units are needed in the refinery along with accompanying additional hydrogen or sulfur capacity because the illustrative process can be conducted as a standalone unit; refinery operations can remain focused on those products that create the greatest value from the crude oil received (i.e. production of petrochemicals, gasoline and distillate (diesel); refiners can continue using the existing slates of crude oils without having to switch to sweeter or lighter crudes to meet the environmental requirements for HMFO products; to name a few.

Heavy Marine Fuel Composition One aspect of the present inventive concept is a fuel composition comprising, but preferably consisting essentially of, the Product HMFO resulting from the processes disclosed, and may optionally include Diluent Materials. As noted above, the bulk properties of the Product HMFO itself complies with ISO8217:2017 and meets the global IMO Annex VI requirements for maximum sulfur content (ISO 14596 or ISO 8754). To the extent that ultra-low levels of sulfur are desired, the process of the present invention achieves this and one of skill in the art of marine fuel blending will appreciate that a low sulfur or ultra-low sulfur Product HMFO can be utilized as a primary blending stock to form a global IMO Annex VI compliant low sulfur Heavy Marine Fuel Composition. Such a low sulfur Heavy Marine Fuel Composition will comprise (and preferably consist essentially of): a) the Product HMFO and b) Diluent Materials. In one embodiment, the majority of the volume of the Heavy Marine Fuel Composition is the Product HMFO with the balance of materials being Diluent Materials. Preferably, the Heavy Maine Fuel Composition is at least 75% by volume, preferably at least 80% by volume, more preferably at least 90% by volume, and furthermore preferably at least 95% by volume Product HMFO with the balance being Diluent Materials.

Diluent Materials may be hydrocarbon or non-hydrocarbon based materials that are mixed into or combined with or added to, or solid particle materials that are suspended in, the Product HMFO. The Diluent Materials may intentionally or unintentionally alter the composition of the Product HMFO but not in a way that the resulting mixture fails to comply with the ISO 8217 (2017) standards for the bulk properties of residual marine fuels or fails to have a sulfur content lower than the global MARPOL standard of 0.5% wt. sulfur (ISO 14596 or ISO 8754). Examples of Diluent Materials that are considered to be hydrocarbon based materials include: Feedstock HMFO (i.e. high sulfur HMFO); distillate based fuels such as road diesel, gas oil, MGO or MDO; cutter oil (which is currently used in formulating residual marine fuel oils); renewable oils and fuels such as biodiesel, methanol, ethanol, and the like; synthetic hydrocarbons and oils based on gas to liquids technology such as Fischer-Tropsch derived oils, fully synthetic oils such as those based on polyethylene, polypropylene, dimer, trimer and poly butylene and the like; refinery residues or other hydrocarbon oils such as atmospheric residue, vacuum residue, fluid catalytic cracker (FCC) slurry oil, FCC cycle oil, pyrolysis gasoil, cracked light gas oil (CLGO), cracked heavy gas oil (CHGO), light cycle oil (LCO), heavy cycle oil (HCO), thermally cracked residue, coker heavy distillate, bitumen, de-asphalted heavy oil, visbreaker residue, slop oils, asphaltene oils; used or recycled motor oils; lube oil aromatic extracts and crude oils such as heavy crude oil, distressed crude oils and similar materials that might otherwise be sent to a hydrocracker or diverted into the blending pool for a prior art high sulfur heavy (residual) marine fuel oil. Examples of Diluent Materials that are considered to be non-hydrocarbon based materials include: residual water (i.e. water that is absorbed from the humidity in the air or water that is miscible or solubilized, in some cases as microemulsions, into the hydrocarbons of the Product HMFO), fuel additives which can include, but are not limited to detergents, viscosity modifiers, pour point depressants, lubricity modifiers, de-hazers (e.g. alkoxylated phenol formaldehyde polymers), antifoaming agents (e.g. polyether modified polysiloxanes); ignition improvers; anti rust agents (e.g. succinic acid ester derivatives); corrosion inhibitors; anti-wear additives, anti-oxidants (e.g. phenolic compounds and derivatives), coating agents and surface modifiers, metal deactivators, static dissipating agents, ionic and nonionic surfactants, stabilizers, cosmetic colorants and odorants and mixtures of these. A third group of Diluent Materials may include suspended solids or fine particulate materials that are present as a result of the handling, storage and transport of the Product HMFO or the Heavy Marine Fuel Composition, including but not limited to: carbon or hydrocarbon solids (e.g. coke, graphitic solids, or micro-agglomerated asphaltenes), iron rust and other oxidative corrosion solids, fine bulk metal particles, paint or surface coating particles, plastic or polymeric or elastomer or rubber particles (e.g. resulting from the degradation of gaskets, valve parts, etc. . . . ), catalyst fines, ceramic or mineral particles, sand, clay, and other earthen particles, bacteria and other biologically generated solids, and mixtures of these that may be present as suspended particles, but otherwise don't detract from the merchantable quality of the Heavy Marine Fuel Composition as an ISO 8217 (2017) compliant heavy (residual) marine fuel.

The blend of Product HMFO and Diluent Materials must be of merchantable quality as a low sulfur heavy (residual) marine fuel. That is the blend must be suitable for the intended use as heavy marine bunker fuel and generally be fungible as a bunker fuel for ocean going ships. Preferably the Heavy Marine Fuel Composition must retain the bulk physical properties that are required of an ISO 8217 (2017) compliant residual marine fuel oil and a sulfur content lower than the global MARPOL standard of 0.5% wt. sulfur (ISO 14596 or ISO 8754) so that the material qualifies as MARPOL Annex VI Low Sulfur Heavy Marine Fuel Oil (LS-HMFO). As noted above, the sulfur content of the Product HMFO can be significantly lower than 0.5% wt. (i.e. below 0.1% wt sulfur (ISO 14596 or ISO 8754)) to qualify as a MARPOL Annex VI compliant Ultra-Low Sulfur Heavy Marine Fuel Oil (ULS-HMFO) and a Heavy Marine Fuel Composition likewise can be formulated to qualify as a MARPOL Annex VI compliant ULS-HMFO suitable for use as marine bunker fuel in the ECA zones. To qualify as an ISO 8217 (2017) qualified fuel, the Heavy Marine Fuel Composition of the present invention must meet those internationally accepted standards including: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s; a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³; a CCAI is in the range of 780 to 870; a flash point (ISO 2719) no lower than 60.0 C a maximum total sediment—aged (ISO 10307-2) of 0.10% wt.; a maximum carbon residue—micro method (ISO 10370) between the range of 18.00% wt. and 20.00% wt., and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.

Production Plant Description: Turning now to a more detailed illustrative embodiment of a production plant implementing both the core process and the oxidative desulfurizing processes disclosed herein, FIGS. 4 and 5 show a schematic for a production plant implementing the core process described above combined with a pre-treatment oxidative desulfurizing unit (FIG. 4, item 2) or a post-treatment oxidative desulfurizing unit (FIG. 5, item 18), the combination which will result in the reduction of the environmental contaminates in a Feedstock HMFO to produce a Product.

It will be appreciated by one of skill in the art that additional alternative embodiments for the core process and the oxidative desulfurizing process may involve multiple vessels and reactors even though only one of each is shown. Variations using multiple vessels/reactors are contemplated by the present invention but are not illustrated in greater detail for simplicity sake. The Reactor System (11) for the core process is described in greater detail below and the use of multiple vessels for the oxidative desulfurizing process has already been described. It will be noted by one of skill in the art that in FIGS. 4 and 5, portions of the production plant with similar function and operation have been assigned the same reference number. This has been done for convenience and succinctness only and differences between FIG. 4 and FIG. 5 are duly noted and explained below.

In FIGS. 4 and 5, Feedstock HMFO (A) is fed from outside the battery limits (OSBL) to the Oil Feed Surge Drum (1) that receives feed from outside the battery limits (OSBL) and provides surge volume adequate to ensure smooth operation of the unit. Water entrained in the feed is removed from the HMFO with the water being discharged a stream (1 c) for treatment OSBL.

As shown in FIG. 4, the Feedstock HMFO (A) is withdrawn from the Oil Feed Surge Drum (1) via line (1 b) by the Oil Feed Pump (3) and sent to the oxidative desulfurizing vessel 2 as a pretreatment step. The pre-treated Feedstock HMFO is pressurized to a pressure required for the process. The pressurized HMFO (A′) then passes through line (3 a) to the Oil Feed/Product Heat Exchanger (5) where the pressurized HMFO (A′) is partially heated by the Product HMFO (B). The pressurized Feedstock HMFO (A′) passing through line (5 a) is further heated against the effluent from the Reactor System (E) in the Reactor Feed/Effluent Heat Exchanger (7).

As shown in FIG. 5, the Feedstock HMFO (A) is withdrawn from the Oil Feed Surge Drum (1) via line (1 b) by the Oil Feed Pump (3) and is pressurized to a pressure required for the process. The pressurized HMFO (A′) then passes through line (3 a) to the Oil Feed/Product Heat Exchanger (5) where the pressurized HMFO (A′) is partially heated by the Product HMFO (B). The pressurized Feedstock HMFO (A′) passing through line (5 a) is further heated against the effluent from the Reactor System (E) in the Reactor Feed/Effluent Heat Exchanger (7).

In both FIG. 4 and FIG. 5, the heated and pressurized Feedstock HMFO (A″) in line (7 a) is then mixed with Activating Gas (C) provided via line (23 c) at Mixing Point (X) to form a Feedstock Mixture (D). The mixing point (X) can be any well know gas/liquid mixing system or entrainment mechanism well known to one skilled in the art.

The Feedstock Mixture (D) passes through line (9 a) to the Reactor Feed Furnace (9) where the Feedstock Mixture (D) is heated to the specified process temperature. The Reactor Feed Furnace (9) may be a fired heater furnace or any other kind to type of heater as known to one of skill in the art if it will raise the temperature of the Feedstock mixture to the desired temperature for the process conditions.

The fully heated Feedstock Mixture (D′) exits the Reactor Feed Furnace (9) via line 9 b and is fed into the Reactor System (11). The fully heated Feedstock Mixture (D′) enters the Reactor System (11) where environmental contaminates, such a sulfur, nitrogen, and metals are preferentially removed from the Feedstock HMFO component of the fully heated Feedstock Mixture. The Reactor System contains a catalyst which preferentially removes the sulfur compounds in the Feedstock HMFO component by reacting them with hydrogen in the Activating Gas to form hydrogen sulfide. The Reactor System will also achieve demetalization, denitrogenation, and a certain amount of ring opening hydrogenation of the complex aromatics and asphaltenes, however minimal hydrocracking of hydrocarbons should take place. The process conditions of hydrogen partial pressure, reaction pressure, temperature and residence time as measured by time space velocity are optimized to achieve desired final product quality. A more detailed discussion of the Reactor System, the catalyst, the process conditions, and other aspects of the process are contained below in the “Reactor System Description.”

The Reactor System Effluent (E) exits the Reactor System (11) via line (11 a) and exchanges heat against the pressurized and partially heats the Feedstock HMFO (A′) in the Reactor Feed/Effluent Exchanger (7). The partially cooled Reactor System Effluent (E′) then flows via line (11 c) to the Hot Separator (13).

The Hot Separator (13) separates the gaseous components of the Reactor System Effluent (F) which are directed to line (13 a) from the liquid components of the Reactor System effluent (G) which are directed to line (13 b). The gaseous components of the Reactor System effluent in line (13 a) are cooled against air in the Hot Separator Vapor Air Cooler (15) and then flow via line (15 a) to the Cold Separator (17).

The Cold Separator (17) further separates any remaining gaseous components from the liquid components in the cooled gaseous components of the Reactor System Effluent (F′). The gaseous components from the Cold Separator (F″) are directed to line (17 a) and fed onto the Amine Absorber (21). The Cold Separator (17) also separates any remaining Cold Separator hydrocarbon liquids (H) in line (17 b) from any Cold Separator condensed liquid water (I). The Cold Separator condensed liquid water (I) is sent OSBL via line (17 c) for treatment.

In FIG. 4, the hydrocarbon liquid components of the Reactor System effluent from the Hot Separator (G) in line (13 b) and the Cold Separator hydrocarbon liquids (H) in line (17 b) are combined and are fed to the Oil Product Stripper System (19). The Oil Product Stripper System (19) removes any residual hydrogen and hydrogen sulfide from the Product HMFO (B) which is discharged in line (19 b) to storage OSBL. The vent stream (M) from the Oil Product Stripper in line (19 a) may be sent to the fuel gas system or to the flare system that are OSBL.

In FIG. 5, the hydrocarbon liquid components of the Reactor System effluent from the Hot Separator (G) in line (13 b) and the Cold Separator hydrocarbon liquids (H) in line (17 b) are combined and are fed to the oxidative desulfurizing unit 18 prior to being sent to the Oil Product Stripper System (19). The Oil Product Stripper System (19) removes any residual hydrogen and hydrogen sulfide from the Product HMFO (B) which is discharged in line (19 b) to storage OSBL. The vent stream (M) from the Oil Product Stripper in line (19 a) may be sent to the fuel gas system or to the flare system that are OSBL.

The gaseous components from the Cold Separator (F″) in line (17 a) contain a mixture of hydrogen, hydrogen sulfide and light hydrocarbons (mostly methane and ethane). This vapor stream (17 a) feeds an Amine Absorber (21) where it is contacted against Lean Amine (J) provided OSBL via line (21 a) to the Amine Absorber (21) to remove hydrogen sulfide from the gases making up the Activating Gas recycle stream (C′). Rich amine (K) which has absorbed hydrogen sulfide exits the bottom of the Amine Absorber (21) and is sent OSBL via line (21 b) for amine regeneration and sulfur recovery.

The Amine Absorber overhead vapor in line (21 c) is preferably recycled to the process as a Recycle Activating Gas (C′) via the Recycle Compressor (23) and line (23 a) where it is mixed with the Makeup Activating Gas (C″) provided OSBL by line (23 b). This mixture of Recycle Activating Gas (C′) and Makeup Activating Gas (C″) to form the Activating Gas (C) utilized in the process via line (23 c) as noted above. A Scrubbed Purge Gas stream (H) is taken from the Amine Absorber overhead vapor line (21 c) and sent via line (21 d) to OSBL to prevent the buildup of light hydrocarbons or other non-condensables.

Reactor System Description: The core process Reactor System (11) illustrated in FIG. 4 and FIG. 5 comprises a single reactor vessel loaded with the process catalyst and sufficient controls, valves and sensors as one of skill in the art would readily appreciate.

Alternative Reactor Systems in which more than one reactor vessel may be utilized in parallel or in a cascading series can easily be substituted for the single reactor vessel Reactor System 11 shown. In such an embodiment, each reactor vessel is similarly loaded with process catalyst and can be provided the heated Feed Mixture (D′) via a common line. The effluent from each of the three reactors is recombined in line and forms a combined Reactor Effluent (E) for further processing as described above. The illustrated arrangement will allow the three reactors to carry out the process effectively multiplying the hydraulic capacity of the overall Reactor System. Control valves and isolation valves may also prevent feed from entering one reactor vessel but not another reactor vessel. In this way one reactor can be by-passed and placed off-line for maintenance and reloading of catalyst while the remaining reactors continues to receive heated Feedstock Mixture (D′). It will be appreciated by one of skill in the art this arrangement of reactor vessels in parallel is not limited in number to three, but multiple additional reactor vessels can be added as shown by dashed line reactor. The only limitation to the number of parallel reactor vessels is plot spacing and the ability to provide heated Feedstock Mixture (D′) to each active reactor.

In another illustrative embodiment cascading reactor vessels are loaded with process catalyst with the same or different activities toward metals, sulfur or other environmental contaminates to be removed. For example, one reactor may be loaded with a highly active demetaling catalyst, a second subsequent or downstream reactor may be loaded with a balanced demetaling/desulfurizing catalyst, and reactor downstream from the second reactor may be loaded with a highly active desulfurization catalyst. This allows for greater control and balance in process conditions (temperature, pressure, space flow velocity, etc. . . . ) so it is tailored for each catalyst. In this way one can optimize the parameters in each reactor depending upon the material being fed to that specific reactor/catalyst combination and minimize the hydrocracking reactions. As with the prior illustrative embodiment, multiple cascading series of reactors can be utilized in parallel and in this way the benefits of such an arrangement noted above (i.e. allow one series to be “online” while the other series is “off line” for maintenance or allow increased plant capacity).

The reactor(s) that form the Reactor System may be fixed bed, ebulliated bed or slurry bed or a combination of these types of reactors. As envisioned, fixed bed reactors are preferred as these are easier to operate and maintain.

The reactor vessel in the Reactor System is loaded with one or more process catalysts. The exact design of the process catalyst system is a function of feedstock properties, product requirements and operating constraints and optimization of the process catalyst can be carried out by routine trial and error by one of ordinary skill in the art.

The process catalyst(s) comprise at least one metal selected from the group consisting of the metals each belonging to the groups 6, 8, 9 and 10 of the Periodic Table, and more preferably a mixed transition metal catalyst such as Ni—Mo, Co—Mo, Ni—W or Ni—Co—Mo are utilized. The metal is preferably supported on a porous inorganic oxide catalyst carrier. The porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier. The preferred porous inorganic oxide catalyst carrier is alumina. The pore size and metal loadings on the carrier may be systematically varied and tested with the desired feedstock and process conditions to optimize the properties of the Product HMFO. Such activities are well known and routine to one of skill in the art. Catalyst in the fixed bed reactor(s) may be dense-loaded or sock-loaded.

The catalyst selection utilized within and for loading the Reactor System may be preferential to desulfurization by designing a catalyst loading scheme that results in the Feedstock mixture first contacting a catalyst bed that with a catalyst preferential to demetalization followed downstream by a bed of catalyst with mixed activity for demetalization and desulfurization followed downstream by a catalyst bed with high desulfurization activity. In effect the first bed with high demetalization activity acts as a guard bed for the desulfurization bed.

The objective of the Reactor System is to treat the Feedstock HMFO at the severity required to meet the Product HMFO specification. Demetalization, denitrogenation and hydrocarbon hydrogenation reactions may also occur to some extent when the process conditions are optimized so the performance of the Reactor System achieves the required level of desulfurization. Hydrocracking is preferably minimized to reduce the volume of hydrocarbons formed as by-product hydrocarbons to the process. The objective of the process is to selectively remove the environmental contaminates from Feedstock HMFO and minimize the formation of unnecessary by-product hydrocarbons (C1-C8 hydrocarbons).

The process conditions in each reactor vessel will depend upon the feedstock, the catalyst utilized and the desired final properties of the Product HMFO desired. Variations in conditions are to be expected by one of ordinary skill in the art and these may be determined by pilot plant testing and systematic optimization of the process. With this in mind it has been found that the operating pressure, the indicated operating temperature, the ratio of the Activating Gas to Feedstock HMFO, the partial pressure of hydrogen in the Activating Gas and the space velocity all are important parameters to consider. The operating pressure of the Reactor System should be in the range of 250 psig and 3000 psig, preferably between 1000 psig and 2500 psig and more preferably between 1500 psig and 2200 psig. The indicated operating temperature of the Reactor System should be 500 F to 900 F, preferably between 650 F and 850 F and more preferably between 680 F and 800 F. The ratio of the quantity of the Activating Gas to the quantity of Feedstock HMFO should be in the range of 250 scf gas/bbl of Feedstock HMFO to 10,000 scf gas/bbl of Feedstock HMFO, preferably between 2000 scf gas/bbl of Feedstock HMFO to 5000 scf gas/bbl of Feedstock HMFO and more preferably between 2500 scf gas/bbl of Feedstock HMFO to 4500 scf gas/bbl of Feedstock HMFO. The Activating Gas should be selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane, so Activating Gas has an ideal gas partial pressure of hydrogen (p_(H2)) greater than 80% of the total pressure of the Activating Gas mixture (P) and preferably wherein the Activating Gas has an ideal gas partial pressure of hydrogen (p_(H2)) greater than 95% of the total pressure of the Activating Gas mixture (P). The Activating Gas may have a hydrogen mole fraction in the range between 80% of the total moles of Activating Gas mixture and more preferably wherein the Activating Gas has a hydrogen mole fraction between 80% and 99% of the total moles of Activating Gas mixture. The liquid hourly space velocity within the Reactor System should be between 0.05 oil/hour/m³ catalyst and 1.0 oil/hour/m³ catalyst; preferably between 0.08 oil/hour/m³ catalyst and 0.5 oil/hour/m³ catalyst and more preferably between 0.1 oil/hour/m³ catalyst and 0.3 oil/hour/m³ catalyst to achieve deep desulfurization with product sulfur levels below 0.1 ppmw.

The hydraulic capacity rate of the Reactor System should be between 100 bbl of Feedstock HMFO/day and 100,000 bbl of Feedstock HMFO/day, preferably between 1000 bbl of Feedstock HMFO/day and 60,000 bbl of Feedstock HMFO/day, more preferably between 5,000 bbl of Feedstock HMFO/day and 45,000 bbl of Feedstock HMFO/day, and even more preferably between 10,000 bbl of Feedstock HMFO/day and 30,000 bbl of Feedstock HMFO/day. The desired hydraulic capacity may be achieved in a single reactor vessel Reactor System or in a multiple reactor vessel Reactor System.

The following example will provide one skilled in the art with a more specific illustrative embodiment for conducting the process disclosed and claimed herein:

Core Process Pilot Unit Set Up: The pilot unit will be set up with two 434 cm³ reactors arranged in series to process the feedstock HMFO. The lead reactor will be loaded with a blend of a commercially available hydro-demetaling (HDM) catalyst and a commercially available hydro-transition (HDT) catalyst. One of skill in the art will appreciate that the HDT catalyst layer may be formed and optimized using a mixture of HDM and HDS catalysts combined with an inert material to achieve the desired intermediate/transition activity levels. The second reactor was loaded with a blend of the commercially available hydro-transition (HDT) and a commercially available hydrodesulfurization (HDS). Alternatively, one can load the second reactor simply with a commercially hydrodesulfurization (HDS) catalyst. One of skill in the art will appreciate that the specific feed properties of the Feedstock HMFO may affect the proportion of HDM, HDT and HDS catalysts in the reactor system. A systematic process of testing different combinations with the same feed will yield the optimized catalyst combination for any feedstock and reaction conditions. For this example, the first reactor was loaded with ⅔ hydro-demetaling catalyst and ⅓ hydro-transition catalyst. The second reactor was loaded with all hydrodesulfurization catalyst. The catalysts in each reactor were mixed with glass beads (approximately 50% by volume) to improve liquid distribution and better control reactor temperature. For this pilot test run, we used these catalysts: HDM: Albemarle KFR 20 series or equivalent; HDT: Albemarle KFR 30 series or equivalent; HDS: Albemarle KFR 50 or KFR 70 or equivalent. Once set up of the pilot unit was complete, the catalyst was activated by sulfiding the catalyst in a manner well known to one of skill in the art.

Core Process Unit Operation: Upon completion of the activating step, the pilot unit was ready to receive the feedstock HMFO and Activating Gas feed. For the present example, the Activating Gas was technical grade or better hydrogen gas. The mixed Feedstock HMFO and Activating Gas was provided to the pilot plant at rates and operating conditions as specified: Oil Feed Rate: 108.5 ml/h (space velocity=0.25/h); Hydrogen/Oil Ratio: 570 Nm3/m3 (3200 scf/bbl); Reactor Temperature: 372° C. (702° F.); Reactor Outlet Pressure:13.8 MPa(g) (2000 psig).

One of skill in the art will know that the rates and conditions may be systematically adjusted and optimized depending upon feed properties to achieve the desired product requirements. The unit was brought to a steady state for each condition and full samples taken so analytical tests were completed. Material balance for each condition was closed before moving to the next condition.

Expected impacts on the Feedstock HMFO properties are: Sulfur Content (wt%): Reduced by at least 80%; Metals Content (wt %): Reduced by at least 80%; MCR/Asphaltene Content (wt %): Reduced by at least 30%; Nitrogen Content (wt %): Reduced by at least 20%; C1-Naphtha Yield (wt%): Not over 3.0% and preferably not over 1.0%.

Process conditions in the Core Process Pilot Unit were systematically adjusted as per Table 1 to assess the impact of process conditions and optimize the performance of the process for the specific catalyst and feedstock HMFO utilized.

TABLE 1 Optimization of Core Process Conditions Nm³ H₂/m³ Pressure HC Feed Rate oil/scf Temp (MPa(g)/ Case (ml/h), [LHSV(/h)] H₂/bbl oil (° C./° F.) psig) Base 108.5 [0.25] 570/3200 372/702 13.8/2000 Baseline T1 108.5 [0.25] 570/3200 362/684 13.8/2000 T2 108.5 [0.25] 570/3200 382/720 13.8/2000 L1 130.2 [0.30] 570/3200 372/702 13.8/2000 L2 86.8 [0.20] 570/3200 372/702 13.8/2000 H1 108.5 [0.25] 500/2810 372/702 13.8/2000 H2 108.5 [0.25] 640/3590 372/702 13.8/2000 S1 65.1 [0.15] 620/3480 385/725 15.2/2200

In this way, the conditions of the core process unit will be optimized to achieve less than 0.5% wt. sulfur product HMFO and preferably a 0.1% wt. sulfur product HMFO. Conditions for producing ULS-HMFO (i.e. 0.1% wt. sulfur product HMFO) will be: Feedstock HMFO Feed Rate: 65.1 ml/h (space velocity=0.15/h); Hydrogen/Oil Ratio: 620 Nm³/m³ (3480 scf/bbl); Reactor Temperature: 385° C. (725° F.); Reactor Outlet Pressure: 15 MPa(g) (2200 psig).

Pre-Treatment Oxidative Desulfurizing Unit Pilot Test: Approximately 1000 gm of Feedstock HMFO (3% wt sulfur) will be placed under and inert atmosphere (preferably nitrogen) and heated to approximately 100° C. (220° F.) to achieve a viscosity suitable for the pumping and flow of the HMFO as a liquid. Reported sulfur specification in heavy petroleum generally indicate that approximately 60%-75% of the sulfur content is attributable to aromatic sulfur compounds such as thiophene>>benzothiophene>>dibenzothiophene. (See for example Sulfur Speciation in Heavy Petroleums: Information from X-ray Absorption Near-Edge Structure, Geoffrey S. Waldo et al., Geochemica et Cosmochimica Acts, Vol, 55 pp 801-814) Based on this approximate speciation, 2% of the sulfur is attributable to thiophene (1.0% wt.) benezothiophene (0.5% wt.) and dibenzothiophene (0.5% wt) or a total aromatic sulfur content of about 0.183 mol equivalents in the sample. Using a molar ratio of 4:1 oxidizing agent to sulfur equivalent, cumyl hydroperoxide is used a titanium promotor poly[bis(glycerolato)(hydroxo)(cumylperoxo)titanium(IV) bisphenol A ester as those disclosed in US 8283498 (incorporated herein by reference) will be added. The oxidant, catalyst and hydrocarbons will remain in contact for a period of 15 minutes which allows the oxidation reactions of sulfur compounds in the hydrocarbon structure to occur. The mixture will then be washed with caustic, such as NaO or the ammonium chloride salt dissolved water. The wash water containing ammonium sulfide and some organic sulfur compounds will then be decanted as stream from the vessel. The HMFO stream containing catalyst and most of the sulfones, as they are more soluble in HMFO than water, will be extracted with methanol to separate the reaction by products sulfoxides and sulfones from the hydrocarbon mixture. The methanol amount used was about equal parts of the treated hydrocarbons to dissolve the oxidation by-products sulfones. About 1 W % of sulfones of total sulfones produced in the oxidation reactions will remain in the HMFO after the extraction process. The HMFO material can then be heated to about 300° C. which will result in the thermal decomposition of the remaining sulfones and the resulting HMFO product °assed with nitrogen or other inert gas. The heated material is subsequently treated in the Core Process Pilot Test Unit described above to give a Product HMFO.

Post-Treatment Oxidative Desulfurizing Unit Pilot Test: Approximately 1000 gm of effluent from the Core Process Pilot Test Unit described above will be placed under and inert atmosphere (preferably nitrogen) and heated to approximately 100° C. (220° F.) to achieve a viscosity suitable for the pumping and flow of the HMFO as a liquid. Based on speciation of the organosulfur compounds, the hard sulfur compounds present substantially include benzothiophene and dibenzothiophene. Diluted ozone (10% by volume in nitrogen) as a gaseous oxidizing agent can be bubbled through the HFMO fluid to oxidize the residual organo-sulfur compounds. Alternatively, a kerosene peroxide (Cu hydroperoxide) generated (as disclosed in U.S. Pat. No. 2,749,284 incorporated herein by reference) and will be mixed in a ratio of one active peroxide equivalent per molar sulfur equivalent or 1.5%-2.0% wt per 1% wt. sulfur present. The mixture will be stirred for approximately 1 hour to simulate a stirred tank reactor. The HMFO containing oxidized sulfur compounds will then be subjected to extraction with methanol using approximately 800 gm methanol divided into five extraction steps. The resulting HMFO product is then fractionated with residual light hydrocarbons and other by-products being removed in a conventional manner.

Table 2 summarizes the impacts on key properties of HMFO by the Core Process Pilot Unit.

TABLE 2 Expected Impact of Process on Key Properties of HMFO Property Minimum Typical Maximum Sulfur Conversion/Removal 90% 95% 99% Metals Conversion/Removal 80% 90% 100%  MCR Reduction 30% 50% 70% Asphaltene Reduction 30% 50% 70% Nitrogen Conversion 10% 30% 70% C1 through Naphtha Yield 0.5%  1.0%  4.0%  Hydrogen Consumption (scf/bbl) 500 750 1500

Table 3 lists analytical tests to be carried out for the characterization of the Feedstock HMFO and Product HMFO. The analytical tests included those required by ISO for the Feedstock HMFO and the product HMFO to qualify and trade in commerce as ISO compliant residual marine fuels. The additional parameters are provided so that one skilled in the art can understand and appreciate the effectiveness of the inventive process.

TABLE 3 Analytical Tests and Testing Procedures Sulfur Content ISO 8754 or ISO 14596 or ASTM D4294 Density @ 15° C. ISO 3675 or ISO 12185 Kinematic Viscosity @ 50° C. ISO 3104 Pour Point, ° C. ISO 3016 Flash Point, ° C. ISO 2719 CCAI ISO 8217, ANNEX B Ash Content ISO 6245 Total Sediment - Aged ISO 10307-2 Micro Carbon Residue, mass % ISO 10370 H2S, mg/kg IP 570 Acid Number ASTM D664 Water ISO 3733 Specific Contaminants IP 501 or IP 470 (unless indicated otherwise) Vanadium or ISO 14597 Sodium Aluminum or ISO 10478 Silicon or ISO 10478 Calcium or IP 500 Zinc or IP 500 Phosphorous IP 500 Nickle Iron Distillation ASTM D7169 C:H Ratio ASTM D3178 SARA Analysis ASTM D2007 Asphaltenes, wt % ASTM D6560 Total Nitrogen ASTM D5762 Vent Gas Component Analysis FID Gas Chromatography or compa- rable

Table 4 contains the expected analytical test results for (A) Feedstock HMFO; (B) the Core Process Product HMFO and (C) Overall Process (Core+post oxidative desulfurizing) from the inventive process. These results will indicate to one of skill in the art that the production of a ULS HMFO can be achieved. It will be noted by one of skill in the art that under the conditions, the levels of hydrocarbon cracking will be minimized to levels substantially lower than 10%, more preferably less than 5% and even more preferably less than 1% of the total mass balance.

TABLE 4 Analytical Results A B C Sulfur Content, mass % 3.0 Less than 0.5 Less than 0.1 Density @ 15° C. 990 950 ⁽¹⁾  950 ⁽¹⁾  Kinematic Viscosity @ 50° C. 380 100 ⁽¹⁾  100 ⁽¹⁾  Pour Point, ° C. 20 10  10  Flash Point, ° C. 110 100 ⁽¹⁾  100 ⁽¹⁾  CCAI 850 820  820  Ash Content, mass % 0.1   0.0   0.0 Total Sediment - Aged, mass % 0.1   0.0   0.0 Micro Carbon Residue, mass % 13.0   6.5   6.5 H2S, mg/kg 0 0 0 Acid Number, mg KO/g 1   0.5   0.5 Water, vol % 0.5 0 0 Specific Contaminants, mg/kg Vanadium 180 20  20  Sodium 30 1 1 Aluminum 10 1 1 Silicon 30 3 3 Calcium 15 1 1 Zinc 7 1 1 Phosphorous 2 0 0 Nickle 40 5 5 Iron 20 2 2 Distillation, ° C./° F. IBP 160/320 120/248 120/248  5% wt 235/455 225/437 225/437 10% wt 290/554 270/518 270/518 30% wt 410/770 370/698 370/698 50% wt  540/1004 470/878 470/878 70% wt  650/1202  580/1076  580/1076 90% wt  735/1355  660/1220  660/1220 FBP  820/1508  730/1346  730/1346 C:H Ratio (ASTM D3178) 1.2   1.3   1.3 SARA Analysis Saturates 16 22  22  Aromatics 50 50  50  Resins 28 25  25  Asphaltenes 6 3 3 Asphaltenes, wt % 6.0   2.5   2.5 Total Nitrogen, mg/kg 4000 3000   3000   Note: ⁽¹⁾ It is expected that property will be adjusted to a higher value by post process removal of light material via distillation or stripping from product HMFO.

It will be appreciated by those skilled in the art that changes could be made to the illustrative embodiments described above without departing from the broad inventive concepts thereof. It is understood, therefore, that the inventive concepts disclosed are not limited to the illustrative embodiments or examples disclosed, but it is intended to cover modifications within the scope of the inventive concepts as defined by the claims. 

1. A process for reducing the environmental contaminants in a Feedstock Heavy Marine Fuel Oil, the process comprising: contacting a Feedstock Heavy Marine Fuel Oil with a oxidizing agent under oxidative desulfurizing conditions to give a pre-treated Feedstock Heavy Marine Fuel Oil; mixing a quantity of the pre-treated Feedstock Heavy Marine Fuel Oil with a quantity of Activating Gas mixture to give a Feedstock Mixture; contacting the Feedstock Mixture with one or more catalysts under desulfurizing conditions to form a Process Mixture from said Feedstock Mixture; receiving said Process Mixture and separating the Product Heavy Marine Fuel Oil liquid components of the Process Mixture from the gaseous components and by-product hydrocarbon components of the Process Mixture and, discharging the Product Heavy Marine Fuel Oil.
 2. The process of claim 1 wherein said Feedstock Heavy Marine Fuel Oil complies with ISO 8217:2017 and has a sulfur content (ISO 14596 or ISO 8754) between the range of 5.0 mass % to 1.0 mass %
 3. The process of claim 1, wherein said Feedstock Heavy Marine Fuel Oil has: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s and a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³ and a CCAI is in the range of 780 to 870 and a flash point (ISO 2719) no lower than 60.0 C and a maximum total sediment—aged (ISO 10307-2) of 0.10 mass % and a maximum carbon residue—micro method (ISO 10370) between the range of 18.00 mass % and 20.00 mass % and a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.
 4. The process of claim 1, wherein the oxidizing agent is selected from the group consisting of a gaseous oxidant, an organic oxidant, an inorganic oxidant, a bio-oxidant or combinations of these.
 5. The process of claim 4, wherein the oxidative desulfurizing conditions include the steps of: contacting the HMFO material with the oxidizing agent to form a HMFO containing oxidized sulfur compounds and separating the HMFO from the oxidized sulfur compounds using a process selected from the group consisting of: thermal decomposition, polar solvent extraction, aqueous caustic wash; selective absorption onto solid absorptive materials and combinations thereof.
 6. The process of claim 1, wherein the catalyst comprises: a porous inorganic oxide catalyst carrier and a transition metal catalyst, wherein the porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier, and wherein the transition metal catalyst is one or more metals selected from the group consisting of group 6, 8, 9 and 10 of the Periodic Table and wherein the Activating Gas is selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane, such that Activating Gas has an ideal gas partial pressure of hydrogen (p_(H2)) greater than 80% of the total pressure of the Activating Gas mixture (P).
 7. The process of claim 6, wherein the hydrodesulfurization conditions comprise: the ratio of the quantity of the Activating Gas to the quantity of Feedstock Heavy Marine Fuel Oil is in the range of 250 scf gas/bbl of Feedstock Heavy Marine Fuel Oil to 10,000 scf gas/bbl of Feedstock Heavy Marine Fuel Oil; a the total pressure is between of 250 psig and 3000 psig; and, the indicated temperature is between of 500 F to 900 F, and, wherein the liquid hourly space velocity is between 0.05 oil/hour/m³ catalyst and 1.0 oil/hour/m³ catalyst
 8. The process of claim 1, wherein said Product Heavy Marine Fuel Oil complies with ISO8217:2017 and has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % to 1.0 mass
 9. The process of claim 8, wherein said Product Heavy Marine Fuel Oil has: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s; and a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³; and a CCAI is in the range of 780 to 870; and a flash point (ISO 2719) no lower than 60.0 C, and a maximum total sediment—aged (ISO 10307-2) of 0.10 mass %, and a maximum carbon residue—micro method (ISO 10370) between the range of 18.00 mass % and 20.00 mass %, and a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % to 1.0 mass %, and a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg, and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.
 10. A process for reducing the environmental contaminants in a Feedstock Heavy Marine Fuel Oil, the process comprising: mixing a quantity of Feedstock Heavy Marine Fuel Oil with a quantity of Activating Gas mixture to give a Feedstock Mixture; contacting the Feedstock Mixture with one or more catalysts under desulfuring conditions to form a Process Mixture from said Feedstock Mixture; receiving said Process Mixture and separating the liquid components of the Process Mixture from the bulk gaseous components of the Process Mixture; receiving said liquid components and contacting the liquid components with a oxidizing agent under oxidative desulfurizing conditions; subsequently separating any residual gaseous components and by-product hydrocarbon components from the Product Heavy Marine Fuel Oil; and, discharging the Product Heavy Marine Fuel Oil.
 11. The process of claim 10 wherein said Feedstock Heavy Marine Fuel Oil complies with ISO8217:2017 and has a sulfur content (ISO 14596 or ISO 8754) between the range of 5.0 mass % to 1.0 mass %
 12. The process of claim 10, wherein said Feedstock Heavy Marine Fuel Oil has: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s and a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³ and a CCAI is in the range of 780 to 870 and a flash point (ISO 2719) no lower than 60.0 C and a maximum total sediment—aged (ISO 10307-2) of 0.10 mass % and a maximum carbon residue—micro method (ISO 10370) between the range of 18.00 mass % and 20.00 mass % and a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg.
 13. The process of claim 10, wherein the oxidizing agent is selected from the group consisting of a gaseous oxidant, an organic oxidant, an inorganic oxidant, a bio-oxidant or combinations of these.
 14. The process of claim 13, wherein the oxidative desulfurizing conditions include the steps of: contacting the HMFO material with the oxidizing agent to form a HMFO containing oxidized sulfur compounds and separating the HMFO from the oxidized sulfur compounds using a process selected from the group consisting of: thermal decomposition, polar solvent extraction, aqueous caustic wash; selective absorption onto solid absorptive materials and combinations thereof.
 15. The process of claim 10, wherein the catalyst comprises: a porous inorganic oxide catalyst carrier and a transition metal catalyst, wherein the porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier, and wherein the transition metal catalyst is one or more metals selected from the group consisting of group 6, 8, 9 and 10 of the Periodic Table; and wherein the Activating Gas is selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane, such that Activating Gas has an ideal gas partial pressure of hydrogen (p_(m)) greater than 80% of the total pressure of the Activating Gas mixture (P).
 16. The process of claim 15, wherein the hydrodesulfurization conditions comprise: the ratio of the quantity of the Activating Gas to the quantity of Feedstock Heavy Marine Fuel Oil is in the range of 250 scf gas/bbl of Feedstock Heavy Marine Fuel Oil to 10,000 scf gas/bbl of Feedstock Heavy Marine Fuel Oil; a the total pressure is between of 250 psig and 3000 psig; and, the indicated temperature is between of 500 F to 900 F, and, wherein the liquid hourly space velocity is between 0.05 oil/hour/m³ catalyst and 1.0 oil/hour/m³ catalyst
 17. The process of claim 10, wherein said Product Heavy Marine Fuel Oil complies with ISO8217:2017 and has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.01 mass % to 1.0 mass %
 18. The process of claim 17, wherein said Product Heavy Marine Fuel Oil has: a maximum kinematic viscosity at 50 C (ISO 3104) between the range from 180 mm²/s to 700 mm²/s; and a maximum density at 15 C (ISO 3675) between the range of 991.0 kg/m³ to 1010.0 kg/m³; and a CCAI is in the range of 780 to 870; and a flash point (ISO 2719) no lower than 60.0° C., and a maximum total sediment—aged (ISO 10307-2) of 0.10 mass %, and a maximum carbon residue—micro method (ISO 10370) between the range of 18.00 mass % and 20.00 mass %, and a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % to 1.0 mass %, and a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg, and a maximum aluminum plus silicon (ISO 10478) content of 60 mg/kg. 